IR 05000335/1990013
| ML17223A818 | |
| Person / Time | |
|---|---|
| Site: | Saint Lucie  |
| Issue date: | 06/11/1990 |
| From: | Crlenjak R, Elrod S, Glasman M, Michael Scott NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17223A816 | List: |
| References | |
| 50-335-90-13, 50-389-90-13, NUDOCS 9006200296 | |
| Download: ML17223A818 (26) | |
Text
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UNITED STATES NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREET, N.W.
ATLANTA,GEORGIA 30323 Report Nos:
50-335/90-13 AND 50-389/90-13 Licensee:
Florida Power 8 Light Co 9250 West Flagler Street Miami, FL 33102 Docket Nos.:
50-335 and 50-389 Facility Name:
St. Lucie 1 and
License Nos.:
DPR-67 and NPF-16 Inspection Conducte il 17 to May 14, 1990 Inspectors.
S.
M.
.
asm Approved By:
en>or i ent nspector ate igne rr at Soigne c)a Date Signed Il 7c)
R.
V.
Cr enja
,
e on hse Division of Reactor Project te
>gne SUMMARY Scope:
This routine resident inspection was conducted onsite in the areas of plant operations review, maintenance observations, surveillance observations, review of nonroutine events, and followup of previous inspection findings.
Results:
The site management provided the site staff with positive guidance during the long and complex Unit
outage.
During this inspection period the operations department was faced with several= challenging situations and performed in an excellent manner.
The maintenance staff and technical support staff resolved multiple issues while always maintaining plant safety as a
priority.
Corporate engineering support of the plant improved since the last Unit 2 outage.
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In addition to the above comments, the outage was extended due to unexpected equipment failures including primary valve packing leaks.
With three startups of Unit
and the intervening shutdowns/cooldowns, the operations department was confronted with many mode change checks.
These checks were handled well.
90062OO ponCK O.OOO33>
From a technical standpoint, the maintenance staff has significantly improved during this'outage.
This has been accomplished by the addition of engineers to the maintenance department.
The maintenance staff has also taken on issues such as pIant aging problems with resulting improvements noted in this area.
During this Unit 1 outage period, Unit 2 had many non-safety maintenance items deferred until the end of the Unit 1 outage.
However, at the end of this inspection period, Unit 2 had only slightly more green maintenance tags hanging in the control room than the 48 present at startup.
During this period, a two week Iong NRC Operational Safety Team Inspection was conducted on site.
Within the areas inspected, one violation, with three examples, was identified:
Failure to seismically support the Unit I equipment hatch drawbridge when required, paragraph 2a.
Failure to control design changes, paragr'aph 2a.
Failure to properly control and install material on the lA ICW pump, paragraph 4.
Within the areas inspected, one unresolved
- item was identified:
UHS valve cycling criteria, paragraph 3.
Unreso ved
>tems are matters about which more information is required to determine whether they are acceptable or may involve violations or deviation REPORT DETAILS Persons Contacted Licensee Employees
- D. Sager, St. Lucie Site Vice President G. Boissy, Plant Manager J. Barrow, Operations Superintendent J.
Barrow, Fire Prevention Coordinator R. Church, Independent Safety Engineering Group H. Buchanan, Health Physics Supervisor
- C. Burton, Operations Supervisor C. Crider, Outage Supervisor
- D. Culpepper, Site Juno Engineering Manager
- R. Dawson, Maintenance Superintendent
- R. Decker, Plant Licensing Engineer
- J. Dyer, guality Control Supervisor R. Englmeier, guality Assurance Superintendent R. Frechette, Chemistry Supervisor
- C. Leppla>
IEC Supervisor L. tlcLaughlin, Plant licensing Superintendent
- L. Rogers, Electrical Maintenance Supervisor N. Roos, Services Manager
- D. West, Technical Staff Supervisor J. West, Mechanical Maintenance Supervisor W. White, Security Supervisor'.
Wood, Reliability and Support Supervisor
- E. Wunderlich, Reactor Engineering Supervisor Chairman Other licensee employees contacted included engineers, technicians, operators, mechanics, security force members and office personnel.
- Attended exit interview Acronyms and initialisms used throughout this report are listed in the last paragraph.
Review of Plant Operations (71707)
Unit
began the inspection period having just attained initial criticality following refueling and then shut down to change the 1A2 RCP shaft seal.
The unit was started up again then shut down to correct identified RCS leakage prior to startup and ceanencement of power production.
The unit ended the inspection period at power; day S
on line.
Unit 2 began and ended the inspection period at power, day 116 on lin a.
Plant Tours The inspectors periodically conducted plant tours to verify that monitoring equipment was recording as required, equipment was properly tagged, operations personnel were aware of plant conditions, and plant housekeeping efforts were adequate.
The inspectors also determined that appropriate radiation controls were.properly established, critical clean areas were being controlled in accordance with procedures, excess equipment or material was stored properly and combustible materials and debris were disposed of expeditiously.
During tours, the inspectors looked for the existence of unusual fluid leaks, piping vibrations, pipe hanger and seismic restraint settings, various valve and breaker positions, equipment caution and danger tags, component positions, adequacy of fire fighting equipment, and instrument calibration dates.
Some tours were conducted on backshifts.
The frequency of plant tours and control room visits by site management was noted to be adequate.
The inspectors routinely conducted partial walkdowns of ESF, ECCS and support systems.
Valve, breaker, and switch lineups and equipment conditions were randomly verified both locally and in the control room.
The following accessible-area ESF system walkdowns were made to verify that system lineups were in accordance with licensee requirements for operability and equipment material conditions were satisfactory:
Unit
CCW platform, post outage Unit
CST Unit
AFW Unit
ICW structure Unit 1 NFIV Control Air System Unit 2 CST Unit 2 ICW structure, during maintenance During a Unit 1 containment tour in mode 4, after the unit was prepared for startup, the equipment drawbridge inside containment was observed to be in the stored (raised)
position supported by a chainfall.
Seismic drawing 8770-G-796, sheet 3,
shows the seismic storage supports for the drawbridge to be a
pair of 3 x 3 inch angle supports about 7 feet long and bolted to the bridge and adjacent deck.
After this was identified, the licensee obtained proper supports and installed them prior to the next criticalit CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, as implemented by approved FPL Topical Quality Assurance Report TQAR 1-76A, Rev 15, TQR 5.0, Instructions, Procedures, and Drawings, and further implemented by TQAR Appendix C
commitment to ANSI 18.7, 1976, paragraph 5.2.7, Maintenance and Modifications, requires that maintenance or modifications which may effect functioning of safety-related structures, systems,.
or components shall be performed in a
manner to ensure quality at least equivalent to that specified in original design bases and requirements, materials specifica-tions and inspection requirements.
Failure to seismically support the drawbridge after the completion of maintenance/
outage activities is an example of an activities not performed in a manner to ensure quality at least equivalent to that in a specified in original design requirements.
This is violation 335,389/90-13-01.~
During a Unit 1 containment tour, the seismic mounting for Hydrogen sampling system containment isolation valves FSE-27-1 through 7 appeared identical but had several different bolting configurations.
The licensee was asked to confirm the approved design configuration.
Because the maintenance organization could not locate an approved drawing to confirm the approved bolting configuration, they then designed and installed significantly different fasteners without design organization approval.
Installing an informal design change was a violation of 10 CFR 50, Appendix B, Criterion III.
This is the second example of violation 335,389/90-13-01.
b.
Plant Operations Review The inspectors periodically reviewed shift logs and operations records, including data sheets, instrument traces, and records of equipment malfunctions.
This review included control room logs and auxiliary logs, operating orders, standing orders, jumper logs and equipment tagout records.
The inspectors routinely observed operator alertness and demeanor during plant tours.
During routine operations, control room staffing, control room access and operator performance and response actions were observed and evaluated.
The inspectors conducted random off-hours inspections. to assure that operations and security remained at an acceptable level.
Shift turnovers were observed to verify that they were conducted in accordance with approved licensee procedures.
Control room annunciator status was verifie The inspectors reviewed the following safety-related tagouts (clearances):
2-3-375, tag 18 - Continuous Oxygen Analyzer 1-4-2, Administrative Control of Equipment, tag 50 - Reject Regulator to the Unit 2 CST 1-4-2, Administrative Control of Equipment, tags 74 - 91, MSIV Air Control System Unit 1 lA2 RCP Shaft Seal Replacement NRC report 335,389/90-11 discussed the initial Unit 1 startup from the refueling outage, subsequently, the decision was made by plant management to replace the RCP 1A2 shaft seal package
- which was not sealing properly.
On May 16 during the shutdown, valves V 1454 and V 1455, series manual isolation valves on a line from the pressurizer high point vent to the containment sump, were tagged open to provide a vent path for the RCS partial draining to support the seal work.
Administrative clearance 1-4-1, involving these valves among others, had been previously issued to maintain valve closure control but was temporarily lifted for this work.
On April 19th, the RCP shaft seal had been replaced and preparations begun for a
second startup.
At approximately 3:00 pm, as RCS pressure was being increased, higher than normal leakage into the containment sump was noted.
Unaware of the leakage, a non-licensed operator had entered containment with clearance tags to again shut the V 1454 and V 1455 valves.
Mhen the non-licensed operator in the containment was directed to investigate the leakage, he immediately knew the leak source.
He shut the two valves and hung the tags for clearance 1-4-1.
Subsequent licensee review of the events and procedures revealed that there was no requirement to check that temporarily lifted clearances were dispositioned prior to commencing plant heatup, i.e., entering mode 4.
Based on that evaluation, the licensee had generated procedure changes to procedures OP 2-0030121, Rev 29, Reactor Plant Heatup - Cold to Hot Standby and AP 0010728, Rev 3, Post Outage Review, to clarify the necessary reviews.
Although there was no requirement at the time for the review of temporarily lifted clearances prior to the mode change, the licensee had initiated the rehanging of clearance 1-4-1 tags on the subject valves.
The timing of the rehanging had caused the unexpected leakage.
Unit 1 Startup Following 1A2 RCP Shaft Seal Replacement
On April 23, the inspectors observed the Unit 1 startup (per OP 1-0030122, Rev 37, Reactor Startup) after the recent RCP shaft seal replacement outage.
The following equipment problems were by the inspectors:
Neither the
"B" train 15 percent feedwater bypass nor the
"B" train main feedwater controller operated in automatic and the
"A" train main feed water controller did not operate well in automatic.
The
"B" train problems stemmed from blown valve controller fuses.
The fuses were blown a few days earlier when auxiliary transformer breaker 20301 failed (discussed in the outage section).
The feed water controller fuses are not normally operationally checked prior to each startup.
The unit was started up in manual feedwater control with sufficient operational attention to prevent a unit trip.
The "A" train main feed water regulating valve and its associated controls were trouble shot at low power and the control air set pressure was adjusted.
During the early stages of the startup, AFAS channel 1 failed when a steam pressure instrument transmitter failed high; The plant operators, who had double shift manning for the startup, assessed the problem and placed the tripped channel in bypass within minutes of its failure.
By the following shift, the AFAS had been repaired and the channel returned to service.
One DEH system pump for the turbine control oil would not produce the required pressure when operationally checked.
Star tup was continued without this backup pump.
The pump was replaced by the next day.
The turbine generator was not placed on line until April 25 due to the main feedwater regulating valve control problems and an exciter weight balance addition.
Unit 1 Shutdown Because of a RCS Higher Than Normal Leak Rate On the night of May 3, Unit 1 shut down to cold conditions due to a higher than normal RCS leak rate of 2.5 gpm to the RDT.
The leakage was primarily coming from the packing of the 'two PORV block valves, MV 1403 and MV 1405.
The 'unit had started up with less than 1.0 gpm packing leakage from these valves.
The inspectors observed control room activities involving the cooldown and preparations for entry into mode 4 per OP 1-0030127, Rev 44, Reactor Plant Cooldown - Hot Standby to* Cold Shutdown.
The operators were us,ing the procedure and plotting the cooldown.
The SDCHXs were warmed up per the procedure prior to placing them in service.
SDC hot leg isolation valves V 3480 and V 3652, which
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automatically close to protect the SDC piping from overpressure, would not open when desired because the pressure indicator/
controller PIC-1104 interlock setpoint had drifted.
The procedure was stopped at that point and the controller was recalibrated.
Paragraph 4 below discusses the findings of the licensee's valve packing problem review.
During the shutdown, seven valves were repacked.
Two of the remotely operated letdown isolation valves were also known to have limited leakage and were also repacked as a
precaution.
Unit
Heatup Following Yalve Repacking
- Loss of Shutdown Cooling On May 7, while solid in mode 5, Unit
RCS pressure was being raised in preparation for drawing a pressurizer bubble.
Charging and letdown were in service.
When plant pressure reached 250 psig, the letdown control valve shut, isolating letdown.
With charging still in service, RCS pressure quickly increased to 290 psig before prompt operator action to stop the pump halted the pressure increase.
The pressure increase caused the SDC hot leg suction valves to shut, as designed, causing a loss of shutdown cooling.
Shutdown cooling was restored in less than five minutes.
TS 3.4.1.4.1 was entered For the five minute period because only one SG had greater than
percent narrow range level.
The operators'esponse to this event was commendable.
Their prompt actions prevented a challenge to the OMS or an inadvertent RCS overpressurization.
The licensee promptly investigated the incident/root cause and determined that improperly installed/
swapped labels between the regenerative HX differential pressure transmitter sensing line isolation valves resulted in an incorrect valve lineup.
This caused the transmitter to send an erroneous signal isolating letdown.
Subsequently, the licensee verified all identification tags installed by the team which incorrectly installed the problem labels.
The licensee is planning a
more comprehensive verification to be completed in the future.
Unit 1 Startup on May 7 and
The Unit 1 startup on May 7 and 8 was observed.
The unit did not go critical the evening of May 7 within the control band that the licensee had estimated due to extended operations at low power during early core life.
Operations personnel reacted properly and promptly to evaluate the condition, insert CEAs as directed by the procedure, and contact their management.
A new ECC was calculated based on the most recent plant operations.
Subsequently, the reactor achieved criticality within the ECC.
The licensee contacted the fuel vendor for subsequent evaluation of the licensee's analysis.
Following the startup, the power escalation went without incident.
Unit 1 remained at power through the end of the inspection perio c.
Techni cal Speci ficati on Compl iance Licensee compliance with selected TS LCOs was verified. This included the review of selected surveillance test results.
These verifica-tions were accomplished by direct observation of monitoring instrumentation, valve positions, and switch positions, and by review of completed logs and records.
The licensee's compliance with LCO action statements was reviewed on selected occurrences as they happened.
The inspectors verified that plant procedures involved were adequate, complete, and the correct revision.
Instrumentation and recorder traces were observed for abnormalities.
Several pumps and valves were placed into LCO time limits this inspection period and were returned to service in a timely manner.
d.
Physical Protection The inspectors verified by observation.
during routine activities.
that security program plans were being implemented as evidenced by:
proper display of picture badges; searching of packages and personnel at the plant entrance; and vital area portals being locked and alarmed.
The inspectors, as a result of routine plant tours and various operational observations, determined that the general plant and system material conditions were being satisfactorily maintained, the plant security program was being effective, and that the overall performance of pla'nt operations was good.
3.
Surveillance Observations Various plant operations were verified to comply with selected TS requirements.
Typical of these were confirmation of TS compliance for reactor coolant chemistry, RWT conditions, containment pressure, control room ventilation and AC and DC electrical sources.
The inspectors verified that testing was performed in accordance with adequate procedures, test instrumentation was calibrated, LCOs Here met, removal and restoration of the affected components were accomplished properly, test results met requirements and were reviewed by personnel other than the individual directing the test, and that any deficiencies identified during the testing were properly reviewed and resolved by appropriate management personnel.
The following surveillance test(s)
were observed:
Unit 2 Turbine Trip Test 6n April 30, the licensee trouble shot and adjusted the vacuum trip for the Unit 2 turbine generator in accordance with NPWO 7829/62 and procedure 0030150, Rev 23, Secondary Plant Operational Checks and Tests, section 8.4, Testing the Low Vacuum Tri During reduced power operations such as condenser water box cleaning, the reduced condenser vacuum would be closer to the low vacuum trip set point.
'he low vacuum trip had been tripping, for the first trip, at more vacuum than its usual trip band
{26 inches of mercury vice 18 to 22 inches)
then, after a trip reset, tripping at
inches on subsequent tests.
An as-found elevated vacuum trip set point made a turbine and reactor trip more probable.
For all turbine protection trips the trip arms are connected to a
common plate on a
common instrument head; any trip would tilt the plate, which would then open a vent valve to relieve system control fluid pressure from the steam admission valves and trip the tur bine.
The trouble shooting on April 30th suggested that the turbine bearing low oil pressure mechanism, also attached to the trip plate, had some slight mechanical binding that may have been reducing the tripping movement of the trip plate and its associated valve.
The testing was inconclusive because accurate testing of the trip instrument head disassembly could not be completed at power.
The bearing low oil pressure trip was operating at its proper trip point - the actuating arm appeared slightly cocked during its travel.
The vacuum trip was adjusted such that the initial trip actuation occurred at 23 inches of mercury and subsequent actuations occurred at
inches of mercury.
The licensee considered that this trip point reduction would provide sufficient margin to allow condenser, water box cleaning without undue challenge to the plant.
The trip instrument head had been scheduled for complete rework during the next short notice outage.
UHS barrier valve test The technical staff, in conjunction with operations personnel, were observed performing the semi-annual TS surveillance test of the barrier valves between the intake canal and the Indian River in accordance with OP 0360050, Rev 6, Emergency Cooling Water Canal - Periodic Test.
Intake canal water level is normally maintained by large pipes from the Atlantic Ocean.
If that source were to fail, barrier valves between the Indian River and the canal could be opened to supply emergency water to the canal.
The two barrier valves, I-SB-37-1 and I-SB-37-2, are 52-inch diameter butterfly valves that fail open under spring power; air pressure normally maintains the valves shut.
To test the valves, air pressure is removed and the valves open.
Due to EPA restrictions on the use of Indian River water, the valves cannot be open for testing more than two minutes per cycle attempt.
The valve operator springs were replaced around 1983 when the valves would not operate properly in either the open or closed direction due to marine fouling and corrosion weakened springs.
During this test, valve 37-1 fully opened under spring power in 45 seconds.
Valve 37-2 initially opened three-quarters of the way and would
.not move any further in one minute. and forty-five seconds.
Due to the EPA restrictions, the valve was then closed using air pressure.
Ninutes later, the valve was again given an open signal and fully opened in 54
s I
seconds with a slight hesitation at the three-quarter position.
The test procedure provided no opening time criteria and did not provide
, instructions for this particular situation.
The TS 4.7.5.1.2 surveillance requirement (both units) required that the valves be demonstrated operable at least once per six months by cycling each valve through at least one complete cycle of full travel.
The requirement is that the equipment must operate from ambient conditions the first time upon demand.
The licensee's position on this point was that, although the valve took two tries to cycle full open, the valve was operable.
Additional licensee points were:
Butterfly valves, at one-quarter open, have nearly full flow and that was sufficient to supply the plant during emergency conditions.
Recent inspection by divers showed the valve to be free of marine growth.
The valves have been inspected and/or cleaned on at least an outage basis.
Additionally, The TS action statement required opening of an inoperable barrier valve within a cumulative 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br />.
This could be readily performed by site personnel should the valve ever become inoperable.
The valves currently were not in the ASME Code Pump and Valve Program and did not have associated opening time restrictions from other regulatory sources. [It is noted that the licensee will soon resubmit their pump and valve program for NRC.
The resubmittal will probably contain a test exemption for the subject valves.]
It was not clear that the TS surveillance and action statements were in concert with the FSAR statement that the licensee had 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to open the valves and that one valve was sufficient for both units.
This item has been identified as URI 335,389/90-13-02 pending NRC review of TS 3/4.7.5. 1.2.
and the relation of the surveillance requirements to the TS action statement.
The performance of AP 0010125A, Rev 15, Data Sheet 15, Monthly Pump Code Run - IB Charging Pump, was observed from the control room.
The data sheet stated that the surveillance must be run at normal operating pressure (about 2250 psig).
The data sheet had no place to record actual test conditions if they were different.
However, this test was run at 458 psig during a
cooldown.
It was also the designated pump operability test following maintenance.
The operator conducting the test understood the directions and also understood that without an operable pump, the plant would never get to 2250 psig to test it.
He wrote a note on the test copy explaining the test
4'
conditions.
Subsequent review by the technical staff found that the procedure was poor in that the normal pressure requirement was present to support ASME Code Pump and Valve Program periodic test requirements and not to prohibit procedure performance at other pressures for other purposes, such as surveillance testing.
The technical staff was reviewing other data sheets thought to contain similar weaknesses and submitting procedure change requests when necessary.
4.
Maintenance Observation (62703)
Station maintenance activities involving selected safety-related systems and components were observed/reviewed to ascertain that they were conducted in accordance with requirements.
The following items were considered during this review:
LCOs were met; activities were accomplished using approved procedures; functional tests and/or calibrations were performed prior to returning components or systems to service; quality control records were maintained; activities were accomplished by qualified personnel; parts and materials used were properly certified; and radiological controls were implemented as required.
Work requests were reviewed to determine the status of outstanding jobs and to assure that priority was assigned to safety-related equipment.
Portions of the following maintenance activities were observed:
HPWO 3813/62 inspected and recapped an isolated portion of the pressurizer relief quench tank cooling water jacket.
To reduce thermal load on the quench tank and to reduce the likelihood of a steam release into containment from a valve primary relief lift, a cooling jacket was installed around 1980.
The jacket cooling was supplied by CCW via the RCP cooling line such that if the quench tank jacket developed a leak it would jeopardize RCP cooling.
At some time in the past, one of the eight cooling jacket segments developed a leak and was capped off; the repair and materials used were not documented.
Upon recent rediscovery, the capped-off cooling jacket segment was found to be holed but not required for tank cooling.
An evaluation of both the capped-off jacket segment and the caps used to isolate it was written and the caps were replaced with material of known quality.
'I NPWO 0866 repaired the 2A MFW pump after the shaft-driven mechanical lubricating oil pump failed.
The backup motor-driven oil pump operated properly until reactor power could be reduced such that the plant could operate on the 2B MFP alone while the 2A MFP was repaired.
The feed pump was coupled to the mechanical lubricating oil pump via a small fractional-horsepower coupling that was covered by the oil pump housing.
The licensee hypothesized that the 0.010
inch diameter coupling lubricating oil channel in the oil pump's shaft clogged and that lead to the failure.
The original 30-year-old design coupling was no longer available from the vendor.
The replacement coupling hub was made of plastic and did not require lubrication.
The licensee inspected the Unit
MFPs during the outage prior to power operation and issued a
NPWO for the 2B MFP for the next short notice outage.
Paragraph 2.b discussed the second Unit 1 post outage shutdown for the repair of seven RCS boundary valves with stem leakage, such as PORV block valve V 1405.
NPWOs 2502/61 to 2509/61 covered the work.
Part of the work effort during valve disassembly involved inspection and documentation of the packing condition and valve pieces/parts condition for the establishment of a root cause.
Concerning three valves repacked this outage by a contractor, it became apparent that the contractor improperly sequenced the packing rings and/or installed an insufficient number of packing rings in at least two valves.
The third valve's packing had severe steam damage and could not be evaluated.
The remaining four valves'acking had some leakage due to packing age, i.e.,
the length of time in service.
The licensee's corrective actions include special repacking instructions to be available for the Unit 2 outage in September 1990.
The licensee was also evaluating further controls/interactions with the repacking contractor(s).
NPWO 0065/61 manufactured and repaired the anti-rotation device on valve MV 09-11, the 1C AFW pump discharge flow control valve to the 1A SG.
The device had failed during valve motor problem trouble shooting.
The device was installed with no instructions save for skill of the craft; after experimenting with assembly of the valve-stem-to-operator connection for approximately 15 minutes, the mechanic working the job figured out the complex intricacies of the parts and completed the work.
The DC motor of the MV 09-11 was beginning to fail under normal operation and exhibited smoke prior to the operations staff securing it.
The motor was replaced and the failed motor was sent for evaluation by a motor overhaul contractor.
The motor's internal parts were found to be binding/rubbing sufficiently to cause additional load for the motor; the contractor thought that the motor had been assembled at the factory with the binding condition.
The licensee was still evaluating the situation.
Paragraph 2.b above mentioned problems with breaker 20301, the auxi1 iary transformer breaker to the 182 4160V bus.
Several Westinghouse circuit breakers with model numbers 50DHP350 and 75DHP500 were eventually involved.
The problem with this breaker
and other breakers of its size and importance was discussed in LER 335/90-005.
On April 18, 1990, while Unit
was in mode 5, the subject breaker was being racked in to prepare for a unit startup.
Unexpectedly, when the breaker's control fuses were installed, the breaker closed.
This caused the energized 18 startup transformer to be shorted to the deenergized main generator and deenergized main transformers.
As a result, the 18 startup transformer feeder breaker to the 284 4160V bus then tripped on overcurrent.
Oue to the subsequent
"8" train power loss, the
EDG started and loaded.
Excessive wear on the breaker closing mechanism mounting plates allowed the closing latch mechanism to move excessively and thus prevented the closing latch from performing its design function; the breaker charging spring motor charged the closing spring but the closing latch would not latch the mechanism.
This allowed the breaker to close as soon as the closing spring was charged.
Other than the excessive wear on the breaker, no other equipment was damaged during the event.
Similar Unit 1 breakers were examined for wear and, although still functional, four additional breakers were sent to a
vendor (ABB) repair facility where a weld repair was performed.
Similar Unit 2 breakers -.were scheduled for inspection during an outage later this year.
Failures of this type had been previously identified by the repair vendor during, the overhaul of these breaker models for other facilities.
No inspection criteria was provided in the manufacturer's technical manual for the parts involved.
This potentially generic issue will be identiFied to NRC management for review; the licensee has not found a saFety-related problem with this flaw and no
CFR Part 21 report has been issued.
For those maintenance activities observed, the inspectors determined that they were conducted in a satisfactory manner and that the work was properly performed in accordance with approved maintenance work orders.
No violations or deviations were identified in the performance of the above NPWOs.
The inspector observed overhaul activities during the ongoing Unit
outage.
As the outage was being completed, the inspectors toured the ICW pump facilities and identified several deficiencies associated with the 1A ICW pump.
The pump was cooled and lubricated by water from a safety-related lubricating supply that attached to the pump via two flanged lines.
One of the lines had a rubber gasket at its flange connection while the other had an.insulation kit consisting of one insulator flanked by rubbet gaskets.
Orawing 8770-B-124, CW 53, Rev 1, Circ. Water System, required that the insulation kits be installed; procedure N-3.55, Rev 0,
Insulation Flange Installation Standard, was the applicable procedure that had been invoked in the NPWO for properly
l h
installed kits.
The NPWO 1506/61 mechanics'rite-up, completed during the recent outage, indicated that the second insulation kit was not installed based on a hold request by the job foreman; the NPWO had been closed.
Once identified, new instructions were quickly issued and the joint repaired.
The stuffing box, which contained the pump shaft packing and is a
pressure boundary, was attached to the pump casing by a bolting ring of studs and three-quarter inch nuts.
The existing nuts were rusted and magnetic, indicating carbon steel material.
The rust had not substantially attacked the nut material such that structural integrity was effected.
Ebasco Specification 53-47, Centrifugal and-Rotary Pumps and Accessories, Intake Cooling Mater Pumps (Purchaser's Identification Spec.
No.
FLO-8770. 121 of dune 25, 1969),
indicated that the subject nuts were type 316 stainless steel, not carbon steel.
The adjacent 1B and 1C pumps'uts appeared to be of the correct material.
The lA stuffing box was last removed in August, 1989 (NPWO 0678/61). It could not be determined whether or not the nuts were replaced; the NPWO package indicated that material was drawn from stores and that no material was turned in to stores for reuse.
A check of the stores bin revealed that 'there were two different styles makes of nuts (standard hex and heavy hex) available, one of which was stamped 316 and both stainless steel.
The following documents and procedures required that appropriate, per-plan materials be installed in safety-related applications:
'ppendix B of 10 CFR 50. Criteria VIII (incorrect or defective material)
FP&L Topical guality Assurance Report, Procedure gP 8.1, section 5.3 ANSI N45.2 - 1971, guality Assurance Program Requirements for Nuclear Power Plants, section
gI 8-PR/PSL-1, Rev 10, Identification, Control of Materials, Parts, and Components, Section 2.2 The first three documents above have fairly explicit requirements that indicate that incorrect material shall not be installed in nuclear plants.
The fourth procedure above, the site implementing procedure, stated that control is necessary to prevent inadvertent use or installation of items that could create non-conformances to regulatory requirements.
Aside from the controls in the procedure section for receipt inspection and storage, there was a
lack of explicit
direction covering material control after issuance from stores and
'rior to installation.
Additionally, procedures do not cover disposition of non-conforming materials identified during component disassembly.
The fai lure to properly control and install material on the lA ICW pump in the locations noted above is the third example of violation 335,389/90-13-01.
Onsite Followup of Written Nonroutine Event Reports (Units
and 2)
(92700)
LERs were reviewed for potential generic impact, to detect trends, and to determine whether corrective actions appeared appropriate.
Events that were reported immediately were reviewed as they occurred to determine if the TS were satisfied.
LERs were reviewed in accordance with the current NRC Enforcement Policy.
Open - LER 389/89-004)
Open - LER 389/89-009)
LERs 389/89-004 and 389/89-009 remain open for the following reasons:
The subject LERs discussed testing problems/failures with a Unit 2 containment purge valve, FCV 25-5.
The valve failed its LLRT three times since its initial failure; with each failure, the licensee would make a repair attempt and the valve would pass its retest.
More thorough investigation and repair were not possible at power within the time constraint of a four hour action statement; both the operator and valve vendors required more time with which to work.
The licensee finally took positive action to resolve the issue during this inspection period by putting a blind flange on the outboard end of the three-purge-valve series to limit leakage; their stated intent was to repair the valve during the upcoming September refueling outage.
The evaluation and action was documented in inter-office correspondence JPN-PSL-90-0701 of May 4,
1990 (evaluation FPL ID JPN-PSL-90-039, Installation of Blind Flange on Outlet of purge Exhaust Valve FCY-25-6, Ebasco Report No. FL0-91-9.5000, Revision No 1).
The licensee was planning a
followup LER after the valve had been repaired.
{Open - LER 335/90-005)
Paragraph 4 above discusses LER 50-335-90-005 which was still open.
Followup {Units 1 and 2) (92701)
Followup of Maintenance Team Inspection Items The maintenance team inspection identified several procedural inadequacies and concerns with the mechanical MKTE program.
These concerns included the lack of centralized control of mechanical METE, and
S
,
procedures which contained errors and did not incorporate vendor recommendations for torque wrench calibration verification.
The inspector reviewed the following subject procedures:
gI 12-PR/PSL-2, Rev 13, Control and Calibration of Measuring and Test Equipment M-0004, Rev 14, Torque Wrench Tester Operation N-0042, Rev 12, draft, Use of N&TE by Mechanical Maintenance The inspector reviewed the licensee's training program and interviewed cognizant personnel to determine if the licensee addressed the concerns identified by the NTI inspection.
The inspectors found that errors identified by the NTI in procedures M-0004, and N-0042 were corrected, or in the process of being corrected.
Major revisions to the mechanical M&TE program included logging the usage of individual N&TE, establishment of calibration intervals for mechanical N&TE, checking torque wrenches and adapters, such as torque multipliers, as a unit'when verifying calibration, and optional deletion of pre/post job calibration verification for non-safety-related work.
However, the licensee indicated to the inspectors that they intend to continue to allow craftsmen to verify calibration of mechanical M&TE in absence of tool room attendants.
The individual craftsmen must complete 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> of training prior to being allowed to verify calibrations and complete their own documentation.
The inspectors reviewed the training materials and found them satisfactory.
With the exception of allowing craftsmen to verify calibration of mechanical M&TE, the concerns identified by the NTI in the area of mechanical M&TE were addressed and appropriate changes made.
In summary, the program was found to meet regulatory requirements concerning M&TE.
Licensee guality Assurance Program Implementation (35502)
An internal office evaluation concerning the licensee's quality assurance program implementation was conducted on May 8, 1990 by reviewing recent inspection reports, SALP reports, open items, licensee corrective actions for NRC inspection findings, and LERs.
Particular emphasis was placed on all new items or findings since the last SALP report period (ending April 30, 1989).
During this. evaluation, it was recognized that team inspections in the areas of maintenance, operational 'safety, design control, and health physics were conducted.
Based on the licensee's current performance and the results of this evaluation, no recommendations were made to increase the inspection effort at St. Luci Exit Interview (30703)
The inspection scope and findings were summarized on May 24, 1990 with those persons indicated in paragraph 1 above.
The inspector described the areas inspected and discussed in detail the inspection findings listed below.
Proprietary material is not contained in this report.
Dissenting comments were not received from the licensee.
Item Number Status Description and Reference 335,389/90-13-01 open VIO - Failure to ensure quality at least equivalent to that specified in the original design bases and requirements, two examples paragraph 2a, third example paragraph 4.
335,389/90-13-02 open URI - Unclear UHS valve cycling criteria, paragraph 3.
Abbreviations, Acronyms, and Initialisms A
AB ABB AC ADV A/E AFAS AFW ALARA ANPO ANPS ANSI AP ASME Code ATI ATWS BCS BOP CAR CCW CE CEA CEDM CEDMCS CET CFR CIS CRAC Ampere(s)
Auxiliary Building ASEA Brown Boveri (company)
Alternating Current Atmospheric Dump Valve Architect/Engineer Auxiliary Feedwater Actuation System Auxiliary Feedwater (system)
As Low as Reasonably Achievable (radiation exposure)
Auxiliary Nuclear Plant )unlicensed]
Operator Assistant Nuclear Plant Supervisor American National Standards Institute Administrative Procedure American Society of Mechanical Engineers Boiler and Vessel Code Automatic Test Instrument (in the ESF cabinets)
Anticipated Transient Without Scram Backfit Construction Sketch
Backfit guality Assurance Procedure
{EBASCO Services Corrective Action Request Component Cooling Water Combustion Engineering (company)
Control Element Assembly Control Element Drive Mechanism Control Element Drive Mechanism Control System Core Exit Thermocouple Code of Federal Regulations Containment Isolation System Control Room Auxiliary Control {panel)
Pressure Inc.)
C IA
CS CST CT CVCS CWO CWO DC DCN DDPS DEH DEV DPR ECC ECCS EDG EOP EPA EPRI ESF F
'DC GE GL GMP gpm HCV HFA HJTC HP HPSI HVE
'HYS HX I8C ICW IFI ILRT IN INPO IR ISI IX JPE Containment Spray (system)
Condensate Storage Tank Current Transformer Chemical Im Volume Control System Control Wiring Diagram Construction Work Order Direct Current Design Change Notice Digital Data Processing System Digital Electro-Hydraulic (turbine control system)
Deviation {from Codes, Standards, Commitments, etc.)
Demonstration Power Reactor (A type of operating license)
Estimated Critical Position Emergency Core Cooling System Emergency Diesel Generator Emergency Operating Procedure Environmental Protection Agency Electric Power Research Institute Engineered Safety Feature Fahrenheit Flow Control Valve Flow Indicator Flow Indicator/Switch The Florida Power Im Light Company Facility Review Group Final Safety Analysis Report Flow Transmitter General Design Criteria (from 10CFR 50, Appendix A)
General Electric Company
[NRC] Generic Letter General Maintenance Procedure Gallon{s) Per Minute (flow rate)
Hydraulic Control Valve A GE relay designation Heated Junction Thermocouple Health Physics High Pressure Safety Injection (system)
Heating and Ventilating Exhaust (fan, system, etc.)
Heating and Ventilating Supply (fan, system, etc.)
Heat Exchanger Instrumentation and Control Intake Cooling Water
[NRC] Inspector Followup Item Integrated Leak Rate Test(ing)
t NRC] Information Notice Institute for Nuclear Power Operations fNRC] Inspection Report InService Inspection (program)
Ion Exchanger (Juno Beach)
Power Plant Engineering
l8 JPN KW LC LCO LER LIV LOI LPSI LT LTOP MATE MCC MFIV MFP MFW MG min MOV MOVATS mrem MP MSIV MSR MTI MV MW NCR NCV NDE NPF NPO NPS NPWO NRC NSSS OI ONOP OP PAP PBT PCM PCV PAID PI PIC PIS PM PORV PSlg ppm (Juno Beach)
Nuclear Engineering KiloWatt(s)
Load Center (electrical distribution)
TS Limiting Condition for Operation Licensee Event Report Licensee Identified Violation Letter of Instruction Low Pressure Safety Injection (system)
Level Transmitter Low Temperature Overpressure Protection (system)
Measuring
'5 Test Equipment Motor Control Center (electrical distribution)
Main Feed Isolation Valve Main Feed Pump Main Feed Water Motor Generator minute Motor Operated Valve Motor Operated Valve Test System millirem Maintenance Procedure Main Steam Isolation Valve Moisture Separator/Reheater Maintenance Team Inspection Motorized Valve Megawatt(s)
Non Conformance Report NonCited Violation (of NRC requirements)
Non Destructive Examination Nuclear Production Facility (a type of license)
Nuclear Plant Operator Nuclear Plant Supervisor Nuclear Plant Work Order Nuclear Regulatory Commission Nuclear Steam Supply System Operating Instruction Off Normal Operating Procedure Operating Procedure Post Accident Panel Performance Based Training Plant Change/Modification Pressure Control Valve Piping 5 Instrumentation Diagram Pressure Indicator Pressure Indicator/Controller Pressure Indicator/Switch Preventive Maintenance Power Operated Relief Valve Pounds per square inch (gage)
Part(s)
per Million
l9 PT PWO PMR QA QC QI QSPDS RAB RCB RCFC RCO RCP RCPB RCS RDT Rev RG RO RPS
,RTGB RVLMS RWT SAL SALP SAS SDC SDCHX SDCS SG SI SIT SNOW SNPO SRO STA Tavg TC TCB TCW TDI TE TEDB TI TMI TR TS URI V
VCT VIO Pressure Transmitter Plant Work Order Pressurized Water Reactor Quality Assurance Quality Control Quality Instruction Qualified Safety Parameter Display System Reactor Auxiliary Building Reactor Containment Building Reactor Compartment Fan Cooler Reactor Control Operator Reactor Coolant Pump Reactor Coolant Pressure Boundary Reactor Coolant System Reactor Drain Tank Revision
.
[NRC] Regulatory Guide Reactor [licensed] Operator Reactor Protection System Reactor Turbine Generator Board Reactor, Vessel Level Monitoring System Refueling Mater Tank
. Service Advice Letter Systematic Assessment of Licensee Performance Safety Assessment System Shut Down Cooling Shut Down Cooling Heat Exchanger Shut Down Cooling System Steam Generator Safety Injection (system)
Safety Injection Tank Short Notice Outage Work Senior Nuclear Plant [unlicensed] Operator Senior Reactor [licensed] Operator Shift Technical Advisor Reactor average temperature Temporary Change Trip Circuit Breaker Turbine Cooling Water Training Department Instruction Temperature Element Total Equipment Data Base
[NRC] Temporary Instruction Three Mile Island Temperature Recorder Technical Specification(s)
[NRC Unresolved Item Volt s)
Volume Control Tank Violation (of NRC requirements)